Optimizing Heavy Oil Recovery Processes Using Electrostatic Desalters

ABSTRACT

The invention relates to improved bitumen recovery processes and systems. The process may include providing a bitumen froth feed stream, separating the stream in a froth separation unit to produce a diluted bitumen stream, treating the diluted bitumen stream in an electrostatic desalter to produce a treated bitumen stream, and separating the treated bitumen stream into a solvent recycle stream and a bitumen product stream. The system may include a combined AC/DC desalter with a control unit for optimizing the treatment process to produce a product bitumen stream using less solvent and smaller separators than conventional bitumen froth treatment plants and processes.

CROSS REFERENCE TO RELATED APPLICATION

This application is a divisional application of U.S. application Ser.No. 12/464,724, entitled OPTIMIZING HEAVY OIL RECOVERY PROCESSES USINGELECTROSTATIC DESALTERS, filed on May 12, 2009, which claims the benefitof U.S. Provisional Application No. 61/133,270, filed Jun. 27, 2008.

FIELD OF THE INVENTION

The present invention relates generally to producing hydrocarbons. Morespecifically, the invention relates to methods and systems for upgradingbitumen in a solvent based froth treatment process using electrostaticdesalting for optimization of the process.

BACKGROUND OF THE INVENTION

The economic recovery and utilization of heavy hydrocarbons, includingbitumen, is one of the world's toughest energy challenges. The demandfor heavy crudes such as those extracted from oil sands has increasedsignificantly in order to replace the dwindling reserves of conventionalcrude. These heavy hydrocarbons, however, are typically located ingeographical regions far removed from existing refineries. Consequently,the heavy hydrocarbons are often transported via pipelines to therefineries. In order to transport the heavy crudes in pipelines theymust meet pipeline quality specifications.

The extraction of bitumen from mined oil sands involves the liberationand separation of the bitumen from the associated sands in a form thatis suitable for further processing to produce a marketable product.Among several processes for bitumen extraction, the Clark Hot WaterExtraction (CHWE) process represents an exemplary well-developedcommercial recovery technique. In the CHWE process, mined oil sands aremixed with hot water to create slurry suitable for extraction as bitumenfroth.

After extraction, the heavy oil slurry (e.g. bitumen froth) may besubjected to a paraffinic froth treatment process. In such a process,the slurry or froth may be introduced into a froth separation unit (FSU)wherein the froth is separated into a diluted bitumen stream and atailings stream. The diluted bitumen stream may be directed to a solventrecovery unit (SRU) for flashing or other processing to produce a hotbitumen product stream and a solvent stream. The hot bitumen productstream may be sent to a pipeline for production and the solvent streammay be recycled in the treatment process.

Electrostatic desalters/dehydrators have been utilized in the oil fieldand at refineries for the purpose of removing contaminants in the oilbeing processed. This generally results in reduced corrosion andfouling, control of trace metal content, and improved wastewatertreatment. See, e.g. SAMS, GARY W. AND WARREN, KENNETH W., New Methodsof Application of Electrostatic Fields, AIChE Spring National Meeting,New Orleans, La., April 2004. Such units may be used in a variety ofconfigurations. See, e.g. U.S. Pat. No. 6,860,979. Electrostaticdesalters may also be used to treat heavy oils. See, e.g. THOMASON,WILLIAM H., ET AL, Advanced Electrostatic Technologies for Dehydrationof Heavy Oils, SPE 97786, November 2005.

Methods to optimize the efficiency of settlers can significantly impactthe efficiency of heavy hydrocarbon (e.g. bitumen) recovery processes.There exists a need in the art for a low cost method to produce pipelinequality hydrocarbons from heavy oil or bitumen.

SUMMARY OF THE INVENTION

In one aspect of the invention, a system of recovering hydrocarbons isprovided. The system includes a bitumen froth inlet stream includingbitumen, water, solids, and at least one paraffinic solvent; a frothseparation unit configured to receive the bitumen froth inlet stream andproduce at least a diluted bitumen stream and a first tailings stream; asolvent recovery unit configured to receive the diluted bitumen streamand produce a product bitumen stream and a solvent recycle stream; andat least one electrostatic desalter configured to receive at least oneof the diluted bitumen stream and the product bitumen stream and producea treated bitumen stream. The system may also include a second frothseparation unit to produce a second diluted bitumen stream to theelectrostatic desalter and a control unit for optimize operation of thedesalter in the system.

In another aspect of the invention, a method for recovering hydrocarbonsis provided. The method includes providing a bitumen froth inlet streamincluding a volume of paraffinic solvents, a volume of water, andasphaltenes; settling out at least a portion of the asphaltenes in afroth separation unit to produce at least a first settled outasphaltenes stream (a first tailings stream) and a diluted bitumenstream; separating the volume of paraffinic solvents from the dilutedbitumen stream in a solvent recovery unit configured to produce aproduct bitumen stream and a solvent recycle stream; and treating atleast one of the diluted bitumen stream and the product bitumen streamin at least one electrostatic desalter to produce a treated bitumenstream. The method may further include providing a second dilutedbitumen stream to the desalter from a second froth separation unit andmay also include controlling certain process conditions to optimize theperformance of the desalter in the process.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other advantages of the present invention may becomeapparent upon reviewing the following detailed description and drawingsof non-limiting examples of embodiments in which:

FIG. 1 is a schematic of a heavy hydrocarbon treatment plant layoutaccording to at least one aspect of the present disclosure;

FIG. 2 is a flow chart of an exemplary heavy hydrocarbon treatmentprocess including at least one aspect of the present disclosure;

FIG. 3 is an illustration of an exemplary electrostatic desalting unitfor use in the plant of FIG. 1 and/or the process of FIG. 2;

FIG. 4 is a schematic of an alternative exemplary bitumen frothtreatment plant layout including at least one aspect of the presentdisclosure; and

FIG. 5 is a schematic of yet another alternative exemplary bitumen frothtreatment plant including at least one aspect of the present disclosure.

DETAILED DESCRIPTION

In the following detailed description section, the specific embodimentsof the present disclosure are described in connection with preferredembodiments. However, to the extent that the following description isspecific to a particular embodiment or a particular use of the presentdisclosure, this is intended to be for exemplary purposes only andsimply provides a description of the exemplary embodiments. Accordingly,the disclosure is not limited to the specific embodiments describedbelow, but rather, it includes all alternatives, modifications, andequivalents falling within the true spirit and scope of the appendedclaims.

The term “asphaltenes” as used herein refers to hydrocarbons which arethe n-heptane insoluble, toluene soluble component of a carbonaceousmaterial such as crude oil, bitumen or coal. One practical test todetermine if oil is an asphaltene is to test whether the oil is solublewhen blended with 40 volumes of toluene but insoluble when the oil isblended with 40 volumes of n-heptane. If so, the oil may be consideredan asphaltene. Asphaltenes are typically primarily comprised of carbon,hydrogen, nitrogen, oxygen, and sulfur as well as trace amounts ofvanadium and nickel. The carbon to hydrogen ratio is generally about1:1.2, depending on the source.

The term “bitumen” as used herein refers to heavy oil. In its naturalstate as oil sands, bitumen generally includes asphaltenes and finesolids such as mineral solids.

The invention relates to processes and systems for recoveringhydrocarbons. In one aspect, the invention relates to a system forrecovering hydrocarbons. The system may include a plant located at ornear a bitumen (e.g. heavy hydrocarbon) mining or recovery site or zone.The plant may include at least one froth separation unit (FSU) having abitumen froth inlet for receiving bitumen froth (or a solventfroth-treated bitumen mixture) and a diluted bitumen outlet for sendingdiluted bitumen from the FSU. The plant also includes a solvent recoveryunit for separating bitumen from solvent to produce a solvent recyclestream and a bitumen product stream. The plant further includes at leastone electrostatic desalter configured to treat either or both of thediluted bitumen stream and the bitumen product stream. Where thedesalter is configured to treat the diluted bitumen stream, the SRU willbe configured to separate the treated bitumen stream. The plant may alsoinclude at least one tailings solvent recovery unit (TSRU), solventstorage unit, pumps, compressors, and other equipment for treating andhandling the heavy hydrocarbons and byproducts of the recovery system.

In another aspect, the invention is a process to partially upgrade abitumen or heavy crude and is particularly suited for bitumen frothgenerated from oil sands which contain bitumen, water, and asphaltenes.The process includes providing a bitumen froth inlet stream havingasphaltenes, paraffinic solvents, and water, settling out at least someof the asphaltenes in a froth separation unit (FSU) to produce a dilutedbitumen stream and a tailings stream, separating the solvents from thediluted bitumen stream in a solvent recovery unit (SRU) to produce abitumen product stream and a solvent recycle stream, and treating eitheror both of the diluted bitumen stream and the bitumen product stream inan electrostatic desalter to produce a treated bitumen stream. In thecase where the treatment is of the diluted bitumen stream, theseparation step separates the treated bitumen stream rather than thediluted bitumen stream.

Referring now to the figures, FIG. 1 is a schematic of an exemplaryparaffinic froth treatment system including certain aspects of thepresent disclosure. The plant 100 receives bitumen froth 102 from aheavy hydrocarbon recovery process. The bitumen froth 102 includesbitumen, water, and at least one paraffinic solvent and is fed into afirst froth separation unit (FSU) 104. A diluted bitumen stream 106 anda tailings stream 114 are produced from the FSU 104. The diluted bitumenstream 106 may be wholly or partly diverted to an electrostatic desalter134 via stream 130. The desalter 134 produces a treated bitumen stream136, which is sent to a solvent recovery unit (SRU) 108, which separatesbitumen from solvent to produce a bitumen product stream 110 and asolvent recycle stream 112. If a portion of the diluted bitumen stream106 is not diverted, then it may be delivered to the SRU 108 via stream106′ without treatment in the desalter 134. In one optional embodiment,the bitumen product stream 110 is sent to an electrostatic desalter 142via line 140 for treatment. Treatment in the desalter 142 may be inaddition to or in lieu of treatment in desalter 134. Further, desalter134 may be the same unit as desalter 142 in some embodiments. Note thatthe SRU 108 may be configured to separate solvent from the dilutedbitumen stream 106 or the treated bitumen stream 136, depending on thelocation of the desalter 134 or 142.

In one exemplary embodiment of the present invention, the desalters 134and 142 include a fresh water inlet stream 131 a having a control valveand a chemical inlet stream 131 b with a control valve (only shown ondesalter 134). The streams are connected to the diluted bitumen stream130 for addition to stream 130. The desalters 134 and 142 alsopreferably include a mixing valve or other such device 132 for mixingthe diluted bitumen stream 130 with either or both of the fresh waterinlet stream 131 a and the chemical inlet stream 131 b. This exemplaryembodiment may further include a control unit 138 having input/outputlines 139 a-139 x for obtaining data from sensors in the system 100 andsending control signals to various parts of the plant 100. The controlunit 138 is preferably an automated unit, but may include some manualoperability such as a manual override, or be completely manuallyoperated. This exemplary embodiment may further include a heating unitto raise the temperature of the diluted bitumen stream 130 (or productbitumen stream 110) to at least about 115 degrees Celsius (° C.) up toabout 150° C.

The control unit is configured to receive at least one data input andmodify at least one process condition to optimize a composition of thetreated bitumen stream 136. The data input may be one or more of thefollowing: a flow rate of the diluted bitumen stream, a flow rate of thefresh water inlet stream, a flow rate of the chemical inlet stream, acomposition of the diluted bitumen stream, a composition of chemicalsflowing through the chemical inlet, an electrostatic fieldcharacteristic, a temperature inside the electrostatic desalter, amixing valve pressure, mixing valve intensity, a temperature of thediluted bitumen stream, a thickness of an emulsion layer, and anycombination thereof. The process condition may be one or more of: theflow rate of the diluted bitumen stream, the flow rate of the freshwater inlet stream, the flow rate of the chemical inlet stream, asolvent content of the diluted bitumen stream, the composition ofchemicals flowing through the chemical inlet, the electrostatic fieldcharacteristic, the temperature inside the electrostatic desalter, themixing valve pressure, the mixing valve intensity, the temperature ofthe diluted bitumen stream, the thickness of an emulsion layer, and anycombination thereof.

In another embodiment, the desalters 134 and 142 may be configured asmultiple desalting units. The desalting units 134 and 142 may bearranged as a multi-stage train such as a two stage train, or may beoperated in parallel, such as by having two parallel single-stage units.Any number of units may be used, which will depend on cost,availability, desired capacity and other operational factors that arebest addressed by a person of ordinary skill in the art on acase-by-case basis.

In an exemplary embodiment of the plant 100, the bitumen froth 102 maybe mixed with a solvent-rich oil stream 120 from FSU 116 in FSU 104.Additionally, the solvent recycle stream 112 may be mixed with tailings114 from the first FSU 104 and fed into a second froth separation unit116. The second FSU 116 produces a solvent rich oil stream 120 and asecond tailings stream 118. The solvent rich oil stream 120 is mixedwith the incoming bitumen froth 102 and the tailings stream is sent to atailings solvent recovery unit 122, which produces a third tailingsstream 124 and a solvent stream 126. In a conventional paraffinic frothtreatment (PFT) plant, the temperature of FSU 104 may be maintained atabout 60 to 80 degrees Celsius (° C.), or about 70° C. and the targetsolvent to bitumen ratio of such prior art systems is about 1.4:1 to2.2:1 by weight or about 1.6:1 by volume on average. In the disclosedplant 100, the target solvent to bitumen ratio is reduced by 10 to 50%from those listed above. This ratio will vary depending on the solidsconcentration in the bitumen, types of solvents used, composition of thebitumen, and other factors. However, it is expected that the desalters134 or 142 are expected to reduce the solids concentration (in parts permillion) by about half. This solvent reduction makes operation of theplant 100 more cost efficient, permits utilization of smaller FSU's 104and 116, and a smaller SRU 108 to treat an equivalent amount of producedbitumen.

The bottom stream 114 from FSU 104 is the tailings substantiallycomprising water, mineral solids, asphaltenes, and some residualbitumen. The residual bitumen from this bottom stream is furtherextracted in FSU 116 by contacting it with fresh solvent (from e.g. 112or 126). The bottom stream 114 of the plant 100 has a lower flow ratethan the bottom stream of a conventional PFT plant and the solvent tobitumen ratio is also lower. In addition, FSU 116 may be smallerrelative to the amount of bitumen recovered in stream 102.

The solvent-rich overflow 120 from FSU 116 may be mixed with the bitumenfroth feed 102. The bottom stream 118 from FSU 116 is the tailingssubstantially comprising solids, water, asphaltenes, and residualsolvent. The bottom stream 118 is fed into a tailings solvent recoveryunit (TSRU) 122, a series of TSRUs or by another recovery method. In theTSRU 122, residual solvent is recovered and recycled in stream 126 priorto the disposal of the tailings in the tailings ponds (not shown) via atailings flow line 124. Exemplary operating pressures of FSU 104 and FSU116 are respectively about 550 thousand Pascals gauge (kPag) and about600 kPag mixed pentane solvents. Other solvents may require a higherpressure to prevent boiling or allow for operation at lower pressures.FSUs 104 and 116 are typically made of carbon-steel but may be made ofother materials.

FIG. 2 is an exemplary flow chart of a process for recoveringhydrocarbons utilizing at least a portion of the equipment disclosed inFIG. 1. As such, FIG. 2 may be best understood with reference to FIG. 1.The process 200 includes providing a bitumen froth inlet stream havingwater, asphaltenes, and solvent 204. Next, the asphaltenes are settledout in a froth separation unit (FSU) to produce a tailings stream and adiluted bitumen stream 206. The solvent is separated from the dilutedbitumen stream in a solvent recovery unit (SRU) to produce a solventrecycle stream and a bitumen product stream 208. Either or both of thediluted bitumen stream and the bitumen product stream are treated in anelectrostatic desalter to produce a treated bitumen stream 210. Note,that certain steps may be repeated and the order of the steps may bealtered. For example, the treatment step 210 may come before theseparation step 208, after the separation step 208, or both. In the casewhere the treatment step 210 comes prior to the separation step 208, theSRU separates the treated bitumen stream rather than the diluted bitumenstream. Optionally, the process 200 may include receiving at least onedata input 212 and controlling at least one process condition toconfigure a composition of the treated bitumen stream bas on the datainput 214.

Still referring to FIGS. 1 and 2, the step of providing the bitumenfroth 204 may include a thermal extraction method such as the clark hotwater extraction (CHWE) method, steam assisted gravity drainage (SAGD),vapor extraction (VAPEX), sliding reservoir bitumen recovery (SRBR),fluidized, in-situ, reservoir extraction (FIRE), cold, heavy oilproduction (CHOPS) or some combination of these methods. An exemplarycomposition of the resulting bitumen froth 102 is about 60 wt % bitumen,30 wt % water and 10 wt % solids, with some variations to account forthe extraction processing conditions. In such an extraction process oilsands are mined, bitumen is extracted from the sands using water (e.g.the CHWE process or a cold water extraction process), and the bitumen isseparated as a froth comprising bitumen, water, solids and air. Duringextraction, air is added to the bitumen/water/sand slurry to helpseparate bitumen from sand, clay and other mineral matter. The bitumenattaches to the air bubbles and rises to the top of the separator (notshown) to form a bitumen-rich froth 102 while the sand and other largeparticles settle to the bottom. Regardless of the type of oil sandextraction process employed, the extraction process will typicallyresult in the production of a bitumen froth product stream 102comprising bitumen, water and fine solids (including asphaltenes,mineral solids) and a tailings stream 114 consisting essentially ofwater and mineral solids and some fine solids.

In the process 200 solvent 120 is added to the bitumen-froth 102 afterextraction and the mixture is pumped to another separation vessel (frothseparation unit or FSU 104). The addition of solvent 120 helps removethe remaining fine solids and water. Put another way, solvent additionincreases the settling rate of the fine solids and water out of thebitumen mixture. Because of the treatment step 210 of the presentprocess 200, less solvent is used and fewer asphaltenes and other solidsare settled out of the bitumen mixture. The treatment step 210 removesmany of these solids in addition to dehydrating the bitumen stream,removing salts, and other impurities. In one embodiment of the recoveryprocess 200 a paraffinic solvent is used to dilute the bitumen froth 102before separating the product bitumen by gravity in a device such as FSU104. Where a paraffinic solvent is used (e.g. when the weight ratio ofsolvent to bitumen is greater than 0.8), a portion of the asphaltenes inthe bitumen are rejected thus achieving solid and water levels that arelower than those in existing naphtha-based froth treatment (NFT)processes. In the NFT process, naphtha may also be used to dilute thebitumen froth 102 before separating the diluted bitumen bycentrifugation (not shown), but not meeting pipeline qualityspecifications.

As would be expected with any process, the preferred conditions seek toproduce the greatest amount of bitumen product 110 with the least amountof expense (e.g. from energy use, chemical use, etc.). Variables thatcould be configured include, but are not limited to: flow rate of thediluted bitumen stream, flow rate of the fresh water inlet stream, flowrate of the chemical inlet stream, solvent content of the dilutedbitumen stream, composition of chemicals flowing through the chemicalinlet, electrostatic field characteristics, temperature inside theelectrostatic desalter, mixing valve pressure, mixing valve intensity,temperature of the diluted bitumen stream, thickness of an emulsionlayer, and any combination thereof. Configuring the preferred conditionsmay be accomplished by obtaining data 212 related to the process 200 andcontrolling process steps 214 like those listed above via manual orautomated control systems such as controller 138.

FIG. 3 is an exemplary illustration of an electrostatic desalting unitfor use in the plant of FIG. 1 and/or the process of FIG. 2. As such,FIG. 3 may be best understood with reference to FIGS. 1 and 2. Thedesalting unit 300 may include a tank 302, an inlet distributor (alsocalled a spreader) 304, an oil collector 306, electrodes 308, and apower unit 310 operatively connected to the electrodes 308. In addition,the desalter 300 includes an inlet flow line 312, a chemical injectionline 314, fresh water injection line 316, a mixing valve 318, and oiloutlet 320 operatively attached to the oil collector 306, and a wateroutlet 322. During standard operation, the desalter 300 may contain atleast three layers of fluids: a water layer 324 at the bottom, anemulsion layer 326 above that, and an oil layer 328 on top of theemulsion layer 326. In addition, when treating heavy oil havingparticulates such as mineral solids and asphaltenes, the solids maysettle at the bottom of the tank. The desalting unit 300 may be eitherof the desalters 130 or 142 and may be utilized in parallel with otherdesalting units or may be configured in stages with other units.

Although all types of electrostatic desalters are within the scope ofthe present disclosure, one preferred type of electrostatic desalter 300utilizes a combined alternating current (AC)/direct current (DC) field.Depending on the composition of the bitumen feed 102, it may bepreferable to utilize a modulated high voltage DC field with AC(MHVDC/AC) type of desalter, bi-modal field modulation (BFM) type ofdesalter, or another type. See, e.g. SPE 97786, supra, which is herebyincorporated by reference for further description of these desaltertypes. The basic electrode 308 configuration is the same for all ofthese types of desalters.

In operation, the desalter 300 mixes the feed stream 312 and/or 130 withfresh “wash water” 314 and/or 131 a and a chemical agent 316 and/or 131b. The combined stream is then mixed in the valve mixer 318 and/or 132to form an emulsion. In general, the AC field is established between thebottom of the electrodes 308 and the oil/water interface and promotesinitial water droplet coalescence. The DC field is generated betweeneach pair of oppositely charged electrodes 308 establishing anelectrostatic voltage field between the electrodes 308. This field is asignificant factor in the dipole force, electrophoretic force, and thedi-electrophoretic force, which are often referred to as “coalescenceforces,” which directly affect the amount of separation of water fromoil droplets.

Some exemplary factors that affect desalter operation and performanceinclude the feed rate and quality of the feed composition,temperature/viscosity/density relationships, electrical field intensity,wash water rate and quality, flow configuration, emulsion formation(e.g. by pumps, exchangers, valves, and mixers, etc.), control of waterlevel and emulsion layers, demulsifier chemicals addition rate, andothers. Treatment of heavy oils having asphaltenes and mineral solidsprovide additional challenges and may require specific solutions such asincreasing the temperature of the desalter to lower the viscosity of theheavy hydrocarbon, increasing the amount of chemical demulsifier todestabilize the solids-stabilized emulsion, and enhanced degassingtechniques. Also, sludge drains and mud washing techniques may beutilized to prevent accumulation of solids in the desalter tank 304.Another optional feature is the use of a highly sensitive level probe tosense the water content of the oil/water interface layer. These andother factors and techniques are discussed in greater detail in WARREN,KENNETH W. AND ARMSTRONG, JOHN, Desalting Heavy Crude Oils—TheVenezuelan Experience, found at: natcogroup.com under Technical Papers,December 2001, which is hereby incorporated by reference for saidtechnical disclosures.

FIG. 4 is an exemplary schematic of an alternative bitumen frothtreatment plant of FIG. 1 utilizing the process of FIG. 2, including thedesalter of FIG. 3. As such, FIG. 4 may be best understood withreference to FIGS. 1-3. The plant 400 includes a bitumen froth inputstream 402 (which may also be mixed with a solvent-rich stream 424) isinput to a froth separation unit (FSU) 404, which separates stream 402into a diluted bitumen component 406 comprising bitumen and solvent anda froth treatment tailings component 412 substantially comprising water,mineral solids, precipitated asphaltenes (and aggregates thereof),solvent, and small amounts of unrecovered bitumen. The tailings stream412 may be withdrawn from the bottom of FSU 404, which may have aconical shape at the bottom, and sent to a second FSU 420, whichproduces a second diluted bitumen stream 422 and a second tailingsstream 426. The second diluted bitumen stream 422 may be combined withthe first diluted bitumen stream 406, with the bitumen feed stream 402,or sent directly to the SRU 408. In the preferred case where at least aportion of the second diluted bitumen stream 422 is combined with thefirst diluted bitumen stream 406, the combined stream is sent via line440 to an electrostatic desalter 300 a for treatment before going to theSRU 408 for separation via line 442. In one alternative embodiment, theproduct stream 410 may be at least partially diverted to anelectrostatic desalter 300 b via line 444 then produced via line 446.

The SRU 408 may be a conventional fractionation vessel or other suitableapparatus in association with other suitable equipment for this purposein which the solvent 414 is flashed off and condensed in a condenser 416associated with the solvent flashing apparatus and recycled/reused inthe process 400. The solvent free bitumen product 410 is then stored ortransported for further processing (e.g. via pipeline) in a manner wellknown in the art or sent to the electrostatic desalter 300 b. Frothtreatment tailings component 412 may be passed directly to the tailingssolvent recovery unit (TSRU) 430 or may first be passed to a second FSU420.

In one embodiment, FSU 404 operates at a temperature of about 60° C. toabout 80° C., or about 70° C. In one embodiment, FSU 404 operates at apressure of about 700 to about 900 kPa, or about 800 kPa. Dilutedtailings component 412 may typically comprise approximately 50 to 70 wt% water, 15 to 30 wt % mineral solids, and 5 to 25 wt % hydrocarbons.The hydrocarbons comprise asphaltenes (for example 2.0 to 12 wt % or 9wt % of the tailings), bitumen (for example about 7.0 wt % of thetailings), and solvent (for example about 8.0 wt % of the tailings). Inadditional embodiments, the tailings may comprise greater than 1.0,greater than 2.0, greater than 3.0, greater than 4.0, greater than 5.0,greater than 10.0 wt % asphaltenes, or about 15.0 wt % asphaltenes.

Still referring to FIG. 4, FSU 420 performs generally the same functionas FSU 404, but is fed the tailings component 412 rather than a bitumenfroth feed 402. The operating temperature of FSU 420 may be higher thanthat of FSU 404 and may be between about 80° C. and about 100° C., orabout 90° C. In one embodiment, FSU 420 operates at a pressure of about700 to about 900 kPa, or about 800 kPa. A diluted bitumen componentstream 422 comprising bitumen and solvent is removed from FSU 420 and iseither sent to FSU 404 via feed 424 for use as solvent to induceasphaltene separation, is at least partially diverted to theelectrostatic desalter 300 a via line 440 for treatment, or is passed toSRU 408 via feed 425 or to an another SRU (not shown) for treatment inthe same way as the diluted bitumen component 406. The ratio of solvent:bitumen in diluted bitumen component 422 may be, for instance, about10:1 to 40:1, or about 20:1. Alternatively, diluted bitumen component422 may be partially passed to FSU 404 via line 424 and partially passedto SRU 408 via line 425, or to another SRU (not shown). Solvent 414 fromSRU 408 may be combined with the diluted tailing stream 412 into FSU420, shown as stream 418, or returned to a solvent storage tank (notshown) from where it is recycled to make the diluted bitumen frothstream 402. Thus, streams 422 and 418 show recycling. In the art,solvent or diluted froth recycling steps are known such as described inU.S. Pat. No. 5,236,577.

In the exemplary system of FIG. 4, the froth treatment tailings 412 ortailings component 426 (with a composition similar to underflow stream412 but having less bitumen and solvent), may be combined with dilutionwater 427 to form diluted tailings component 428 and is sent to TSRU430. Diluted tailings component 428 may be pumped from the FSU 420 orFSU 404 (for a single stage FSU configuration) to TSRU 430 at the sametemperature and pressure in FSU 420 or FSU 404. A backpressure controlvalve 429 may be used before an inlet into TSRU 430 to prevent solventflashing prematurely in the transfer line between FSU 420 and TSRU 430.

Flashed solvent vapor and steam (together 434) is sent from TSRU 430 toa condenser 436 for condensing both water 438 and solvent 440. Recoveredsolvent 440 may be reused in the bitumen froth treatment plant 400.Tailings component 432 may be sent directly from TSRU 430 to a tailingsstorage area (not shown) for future reclamation or sent to a second TSRU(not shown) or other devices for further treatment. Tailings component432 contains mainly water, asphaltenes, mineral matter, and smallamounts of solvent as well as unrecovered bitumen. A third TSRU (notshown) could also be used in series and, in each subsequent stage, theoperating pressure may be lower than the previous one to achieveadditional solvent recovery. In fact, more than three TSRU's could beused, depending on the quality of bitumen, pipeline specification, sizeof the units and other operating factors.

FIG. 5 is yet another exemplary alternative embodiment of a heavy oiltreatment plant in accordance with the present invention. The plantshares many of the components with the plant of FIG. 4, utilizes theprocess of FIG. 2, and includes the electrostatic desalter of FIG. 3. assuch, FIG. 5 may be best understood with reference to FIGS. 2-4. Theplant 500 generally includes three portions, the froth separationportion 501, the solvent recovery portion 503, and the tailings solventrecovery portion 505. Similar to the plant 400, the plant 500 includesat least one desalting unit 300, which may be located in one or all ofthe locations 300 a, 300 b, and 300 c.

As noted, plant 500 includes many similar components as the plant 400and to the extent the schematics look the same, they may be consideredequivalent. For example, the froth separation portion 501 includes FSU's404 and 420, but shows a slightly different flow configuration and aheating unit 507. Additional alternative flow schemes are shown betweenthe froth separation portion 501, the solvent recovery portion 503, andthe tailings recovery portion 505. These flow lines include additionalheaters like 507 as well as separation/accumulation tanks such as 509 aand 509 b. The solvent recovery portion 503 includes a solvent recoveryunit 408 as well as a vacuum system 511 and a steam generation unit 513.These additional units (e.g. 511 and 513) may also be included in plant100 and plant 400, but were not shown for simplicity. They are shown inplant 500 for illustrative purposes and as just one example of a layoutfor a process plant for treating bitumen froth. The plant 500 also morespecifically contemplates a high temperature bitumen treatment process.

While the present disclosure may be susceptible to various modificationsand alternative forms, the exemplary embodiments discussed above havebeen shown only by way of example. However, it should again beunderstood that the disclosure is not intended to be limited to theparticular embodiments disclosed herein. Indeed, the present disclosureincludes all alternatives, modifications, and equivalents falling withinthe true spirit and scope of the appended claims.

1. A method of recovering hydrocarbons, comprising: providing a bitumenfroth inlet stream including a volume of paraffinic solvents, a volumeof water, and asphaltenes; settling out at least a portion of theasphaltenes in a froth separation unit to produce at least a firstsettled out asphaltenes stream (a first tailings stream) and a dilutedbitumen stream; separating the volume of paraffinic solvents from thediluted bitumen stream in a solvent recovery unit configured to producea product bitumen stream and a solvent recycle stream; and treating atleast one of the diluted bitumen stream and the product bitumen streamin at least one electrostatic desalter to produce a treated bitumenstream.
 2. The method of claim 1, wherein the electrostatic desalter isconfigured to remove at least about 10 percent (%) to about 50% of thesolids from the at least one of the diluted bitumen stream and theproduct bitumen stream.
 3. The method of claim 2, further comprisingsettling out at least a portion of the asphaltenes from the firsttailings stream in a second froth separation unit configured to receivethe first tailings stream and produce at least a second diluted bitumenstream and a second tailings stream containing asphaltenes separatedfrom the first tailings stream.
 4. The method of claim 3, wherein theelectrostatic desalter is configured to receive at least a portion ofthe second diluted bitumen stream.
 5. The method of claim 4, wherein theelectrostatic desalter further comprises: an inlet flow conduitoperatively connected to a fresh water inlet configured to deliver afresh water stream to the inlet flow conduit and a chemical inletconfigured to deliver a chemical stream to the inlet flow conduit,wherein the inlet flow conduit is configured to deliver the dilutedbitumen stream to the electrostatic desalter; a mixing valve operativelyconnected to the inlet flow conduit, wherein the mixing valve isconfigured to impart mixing energy to the diluted bitumen stream and asecond stream selected from the group consisting of the fresh waterstream, the chemical stream, and any combination thereof; and an oiloutlet configured to produce the treated bitumen stream.
 6. The methodof claim 5, further comprising: receiving at least one data input; andcontrolling at least one process condition to configure a composition ofthe treated bitumen stream based on the at least one data input.
 7. Themethod of claim 6, wherein the at least one data input is selected fromthe group comprising: a flow rate of the diluted bitumen stream, a flowrate of the fresh water inlet stream, a flow rate of the chemical inletstream, a composition of the diluted bitumen stream, a composition ofchemicals flowing through the chemical inlet, an electrostatic fieldcharacteristic, a temperature inside the electrostatic desalter, amixing valve pressure, a mixing valve intensity, a temperature of thediluted bitumen stream, a thickness of an emulsion layer, and anycombination thereof.
 8. The method of claim 7, wherein the at least oneprocess condition is selected from the group comprising: the flow rateof the diluted bitumen stream, the flow rate of the fresh water inletstream, the flow rate of the chemical inlet stream, a solvent content ofthe diluted bitumen stream, the composition of chemicals flowing throughthe chemical inlet, the electrostatic field characteristic, thetemperature inside the electrostatic desalter, the mixing valvepressure, the mixing valve intensity, the temperature of the dilutedbitumen stream, the thickness of an emulsion layer, and any combinationthereof.
 9. The method of claim 4, further comprising configuring the atleast one electrostatic desalter as a plurality of desalting units in aconfiguration selected from the group consisting of: at least onetwo-stage train and at least two parallel single-stage units.
 10. Themethod of claim 5, wherein the chemical inlet stream includes a chemicaldemulsifier.